The present invention relates generally to the evaluation of wellbore fluids, in particular to the determination of the composition of a multi-component fluid. More specifically, the present invention relates to the determination of the fluid composition of a multi-component fluid using measured physical properties of the fluid. This method is particularly useful in in-situ determination of the quality of wellbore fluid samples.
During drilling operations, a wellbore is typically filled with a drilling fluid (“mud”), which may be water-based or oil-based. The mud is used as a lubricant and aids in the removal of cuttings from the wellbore, but one of the most important functions of mud is well control. Hydrocarbons contained in subterranean formations are contained within these formations at very high pressures. Standard over-balanced drilling techniques require that the hydrostatic pressure in the wellbore exceed the formation pressure, thereby preventing formation fluids from flowing uncontrolled into the wellbore. The hydrostatic pressure at any point in the wellbore depends on the height and density of the fluid column of mud above that point. A certain hydrostatic pressure is desired in order to offset the formation pressure and prevent fluid flow into the well. Thus, it is well known in the art to control the mud density and it is often necessary to use high density “heavy” mud to achieve a desired hydrostatic pressure.
Whenever the hydrostatic pressure of the mud is greater than the pressure of the surrounding formation, drilling fluid filtrate will tend to penetrate the surrounding formation. Thus, the fluid in the formation close to the wellbore will be a mixture of drilling fluid filtrate and formation fluid. The presence of fluid filtrate in the formation can interfere with attempts to sample and analyze the formation fluid. As a fluid sample is drawn from the formation at the wall of the wellbore, the first fluid collected may comprise primarily drilling fluid filtrate, with the amount of filtrate in the mixture typically decreasing as collected volume increases. Because the fluid sought to be analyzed is the wellbore fluid, and not the drilling fluid filtrate, it is desirable to collect a sample containing as little drilling fluid filtrate as is possible.
Early formation testing tools were designed to draw in a fixed volume of fluid and transport that volume to the surface for analysis. It was soon realized that the fixed volume was not sufficient to collect a reasonable sample of formation fluid because the sample would be primarily drilling fluid filtrate. To solve this problem, formation testing tools were developed that were able to continuously pump fluid into the testing tool so that sample collection could be controlled by the operator. Using these types of tools, the operators attempt to avoid collecting filtrate in the fluid sample by pumping for a period of time before collecting the fluid sample. The amount of time used to obtain a filtrate-free sample is based on experience or intuition. The problem with this design is there is still no way to determine the quality of the collected sample without pulling the tool to the surface. Therefore, it is desirable to be able to determine the quality of the fluid sample in-situ, with the formation tester still in the well, in order to increase the efficiency and effectiveness of sample collection.
One method that has been used in an attempt to evaluate the quality of a fluid sample downhole is monitoring of a fluid property over time. One such fluid property is fluid density. There are tools available to measure fluid density downhole and plot the measured density as a function of time. As time increases, the measured fluid density in the sample volume changes until it levels out very close to the density of the formation fluid. This leveling out of the density is known as asymptotic convergence and the value of density at this point is the asymptotic value.
It is usually preferred to acquire a sample of the formation fluid when the measured properties of the sample fluid reach asymptotic levels, which indicates that the amount of filtration in the sample cannot be reduced further. The difficulty with this method is that, although an equilibrium between the amounts of formation fluid and drilling fluid filtrate entering the sample volume has been reached, the level of contamination of the fluid mixture may still not be known. For example, if drilling fluid filtrate is migrating into the formation faster than the sample is being drawn, the asymptotic level reached will still have a high percentage of drilling fluid filtrate. Therefore, there is still required a method for in-situ evaluation of a fluid sample that provides more than a qualitative, or low resolution (±10% or more) quantitative, measure of fluid composition.
One method of in-situ evaluation of fluid composition is described in WO 00/50876 and utilizes optical analysis of a fluid sample to evaluate fluid quality. The method utilizes optical density measurements to create data points to which are then used, by curve fitting techniques, to estimate an asymptotic value for the fluid density. This estimated asymptotic value is assumed to be the optical density of the wellbore fluid and is used to determine the amount of drilling fluid filtrate contamination in a sample. Optical density sensors work by transmitting a light of a specific wavelength through a fluid and measuring the optical absorption. The absorption of light as it travels through the fluid is greatly dependent on the type of hydrocarbons present in the fluid and on the wavelength of the light transmitted. Thus, the use of optical density sensors depends greatly on established knowledge of the type of hydrocarbons found in the formation fluid. This method also assumes an additional function for the change in optical density that is used to predict the asymptote and requires that the fluid be analyzed for a significant period of time before the end point (formation fluid property) can be established. Therefore, optical density evaluation does not provide real-time quantitative assessment of the fluid composition.
Mixing laws are mathematical relationships that have been used to quantify the components of a mixture and describe a property of a mixture in terms of the properties of the constituents. Thus, a the application of a mixing law may allow for the property of the mixture to be predicted if the weighting functions for the constituents, and the properties of the constituents are known. For example, mixing laws have been applied to predicting a variety of properties, including the dielectric properties of mixtures, J. P. Calame, et al, First World Congress on Microwave Processing, Jan. 5–9, 1997, and density of a rock formation as described in http://appliedgeophysics.berkeley.edu:7057/gravity/grav23.pdf.
Consequently, there still exists a need for a method for real-time quantitative assessment of the composition of fluid in a wellbore where little or no information may be available about the formation fluid. The present invention is directed to improved methods for determination of fluid composition in a wellbore that seek to overcome these and other limitations of the prior art.